A choke valve is a throttling device. It is commonly used as part of an oil or gas field wellhead. It functions to reduce the pressure of the fluid flowing through the valve internals. Choke valves are placed on the production “tree” of an oil or gas wellhead assembly to control the flow of produced fluid from a reservoir into the production flow line. They are used on wellheads located on land and offshore, as well as on wellheads located beneath the surface of the ocean.
In general, chokes involve:                a valve body having an axial bore, a body inlet (typically referred to as a side outlet) and a body outlet (typically referred to as an end outlet);        a “flow trim” mounted in the bore between inlet and outlet, for throttling the flow moving through the body; and        means for actuating the flow trim, said means closing the end of the bore remote from the outlet.        
There are four main types of flow trim commonly used in commercial chokes. Each flow trim involves a port-defining member, a movable member for throttling the port, and seal means for implementing a total shut-off. These four types of flow trim can be characterized as follows:                (1) a needle-and-seat flow trim comprising a tapered annular seat fixed in the valve body and a movable tapered internal plug for throttling and sealing in conjunction with the seat surface;        (2) a cage-with-internal-plug flow trim, comprising a tubular, cylindrical cage, fixed in the valve body and having ports in its side wall, and a plug movable axially through the bore of the cage to open or close the ports. Shut-off is generally accomplished with a taper on the leading edge of the plug, which seats on a taper carried by the cage or body downstream of the ports;        (3) a multiple-port-disc flow trim, having a fixed ported disc mounted in the valve body and a rotatable ported disc, contiguous therewith, that can be turned to cause the two sets of ports to move into or out of register, for throttling and shut-off; and        (4) a cage-with-external-sleeve flow trim, comprising a tubular cylindrical cage having ports in its side wall and a hollow cylindrical sleeve that slides axially over the cage to open and close the ports. The shut-off is accomplished with the leading edge of the sleeve contacting an annular seat carried by the valve body or cage.        
In each of the above, the flow trim is positioned within the choke valve at the intersection of the choke valve's inlet and outlet. In most of the valves, the flow trim includes a stationary tubular cylinder referred to as a “cage”, positioned transverse to the inlet and having its bore axially aligned with the outlet. The cage has restrictive flow ports extending through its sidewall. Fluid enters the cage from the choke valve inlet, passes through the ports and changes direction to leave the cage bore through the valve outlet.
Such a flow trim also includes a tubular throttling sleeve that slides over the cage. The sleeve acts to reduce or increase the area of the ports. An actuator, such as a threaded stem assembly, is provided to bias the sleeve back and forth along the cage. The rate that fluid passes through the flow trim is dependent on the relative position of the sleeve on the cage and the amount of port area that is revealed by the sleeve.
Maintenance on the deep subsea wellhead assemblies cannot be performed manually. An unmanned, remotely operated vehicle, referred to as an “ROV”, is used to approach the wellhead and carry out maintenance functions. To aid in servicing subsea choke valves, choke valves have their internal components, including the flow trim, assembled into a modular sub-assembly. The sub-assembly is referred to as an “insert assembly” and is inserted into the choke valve body and clamped into position.
When the flow trim becomes worn beyond its useful service life due to erosion and corrosion caused by particles and corrosive agents in the produced substances, an ROV is used to approach the choke valve, unclamp the insert assembly from the choke valve body and attach a cable to the insert assembly so that it may be raised to the surface for replacement or repair. The ROV then installs a new insert assembly and clamps it into position. This procedure eliminates the need to raise the whole wellhead assembly to the surface to service a worn choke valve.
In order to efficiently produce a reservoir, it is necessary to monitor the flow rate of the production fluid. This is done to ensure that damage to the formation does not occur and to ensure that well production is maximized. This process has been, historically, accomplished through the installation of pressure and temperature transmitters into the flow lines upstream and downstream of the choke valve. The sensor information is then sent to a remote location for monitoring, so that a choke valve controller can remotely bias the flow trim to affect the desired flow rate. The controller sends electrical signals to means, associated with the choke valve, for adjusting the flow trim.
Choke valves common to oil and gas field use are generally described in U.S. Pat. No. 4,540,022, issued Sep. 10, 1985, to Cove and U.S. Pat. No. 5,431,188, issued Jul. 11, 1995 to Cove. A subsea choke valve is described in U.S. Pat. No. 6,782,949, issued Aug. 31, 2004. All of these patents are assigned to Master Flo Valve Inc., the owner of this application.
Control valves, such as choke valves, are often equipped with a means to provide position control. In the most fundamental form, manual operation by a lever or hand wheel is used. To provide remote control of a valve's position a variety of actuators, including hydraulic actuators, can be used.
U.S. Patent Application published Nov. 4, 2004 as US 2004/02116884 and naming Bodine et al. as inventors, describes known hydraulic actuator control systems for subsea chokes as follows:
In offshore oil and gas production, it is often common for more than one well to be produced through a single flow line. In a typical installation, the products from each individual well flow are combined into a common flow line, which then carries the products to the surface or combines those products with the products of other flow lines. The difficulty in managing a multiple well completion produced through a single flow line is that not all of the wells may be producing at the same pressure conditions or include the same flow constituents (liquids and gases).
For example, if one individual well is producing at a lower pressure than the pressure maintained in the flow line, fluid can back flow from the flow line into that well. Not only is the loss of production fluids undesirable, but the pressure changes and reverse flow conditions within that well may damage the well and/or reservoir. Similarly, if one well is producing at a pressure above the flow line pressure, that well may produce at an undesirable flow rate and pressure, again with the potential to damage other wells and/or the reservoir. Thus, the management of flow rates and pressures is of critical importance in maximizing the production of hydrocarbons from the reservoir.
In one prior art subsea production system, control signals and a hydraulic fluid supply are transmitted along an umbilical from a topside control system to a subsea control module which supplies hydraulic fluid to actuators in the subsea trees, manifolds, valves, choke and other functions. As control valves within the control module receive signals to open or close the choke, the control valves actuate to control the flow of hydraulic fluid to the choke actuator through either hydraulic lines opening or closing. A common choke actuator is a hydraulic stepping actuator, which, depending on the style of actuator and choke being used, may take 100 to 200 steps to close, although systems requiring a smaller, or larger, number of steps are possible. Each step involves the actuator receiving a pulse of hydraulic pressure, which moves the actuator, and then a release of that pressure, which allows a spring to return the actuator to its initial position. In typical systems, where the SCM (subsea control module) is located proximate (e.g., within about 30-feet) to the choke/actuator, about one second is required for the pressure pulse to travel from the control valve in SCM to the actuator and two seconds are required for the spring to return the actuator to its initial position. Thus, with a total of three seconds per step and a total of up to 200 or more steps required to fully actuate the choke, the time required to fully close or open the choke is considerable. The risk of equipment failure is also increased due to the components being actuated hundreds, thousands, or even millions, of times.
In another typical prior art subsea production system, control signals and a hydraulic fluid supply are transmitted along an umbilical from a topside control system directly to a subsea choke, bypassing the subsea control module on an electro hydraulic control system. Operation of a direct hydraulic control system would also be as described above, since no subsea control module is required, and a direct electric (control) system would operate similarly, minus any hydraulic control lines. The choke is opened and also closed via hydraulic signals transmitted through dedicated umbilical lines. Hydraulic signals from the surface control the flow of hydraulic fluid to the choke actuator through either hydraulic opening and closing lines. The common choke actuator is a hydraulic stepping actuator which, depending on the style of actuator and choke being used, may take 100–200 steps to close. Each step involves the actuator receiving a pulse of hydraulic pressure, which moves the actuator, and then a release of that pressure, which allows a spring to return the actuator to its initial position. In typical systems, the time required for the pressure pulse to travel from the surface to the actuator is directly related to the offset distance (umbilical length from surface to choke), water depth and actuating pressure, which can be minutes per step for long offsets. Also, an additional amount of time is required for the spring to return the actuator to its initial position. The time to actuate each step can run into minutes, thus, with a total of up to 200 steps required to fully actuate the choke, the time required to fully close or open the choke is considerable.
In yet a third typical prior art subsea production system, electrical power and a hydraulic fluid supply are transmitted along an umbilical from a topside control system directly to a subsea choke actuator system, bypassing the subsea control module on an electro hydraulic control system. Operation of a direct hydraulic control system would also be as described above, since no subsea control module is required, and a direct electric (control) system would operate similarly, minus any hydraulic control lines. A hydraulic fluid supply is stored local to the choke, such as in accumulator. The choke is opened and also closed via electrical signals transmitted through dedicated umbilical conductors to actuate the open and close functions. The electrical signals are received by a directional control valve that regulates hydraulic flow to the open and close functions of choke actuator. For this instance, hydraulic fluid is supplied to the local choke accumulators, which are refilled by the hydraulic supply along an umbilical. The common choke actuator is a hydraulic stepping actuator which, depending on the style of actuator and choke being used, may take 100 to 200 steps to close. Each step involves the actuator receiving an electrical power pulse, followed by a pulse of hydraulic pressure, which moves the actuator, and then a release of the electrical power that releases the hydraulic pressure, which allows a spring to return the actuator to its initial position. In typical systems, roughly one second is required for the electrical power pulse to travel from the surface to the choke, and then for the pressure pulse to travel from the local choke accumulator to the actuator and roughly two seconds are required for the spring to return the actuator to its initial position. Thus, with a total of three to four seconds per step and a total of up to 200 steps required to fully actuate the choke, the time required to fully close or open the choke is considerable. The power requirements for this type of system are considerable, while the umbilical must have electrical conductors (one for open, one for close) for each choke.
U.S. Pat. No. 6,782,952 issued Aug. 31, 2004, discloses a hydraulic stepping valve actuator for moving the sliding sleeve of a downhole well valve. The system relies on a mechanical locking system to restrain the sleeve at each incremental position. As well, the system does not provide a fast close fail system, which is needed in a production well.
There remains a need in the art for systems and methods for increasing the responsiveness and speed of choke control systems, especially subsea systems.